Revised SD Trans Cover Letter · 2010. 12. 21. · REVISED PETITION OF OTTER TAIL POWER COMPANY I. INTRODUCTION. Otter Tail Power Company, (“Otter Tail or Company”), hereby petitions

215 South Cascade Street PO Box 496 Fergus Falls, Minnesota 56538-0496 218 739-8200 www.otpco.com (web site)

An Equal Opportunity Employer

December 21, 2010 Ms. Patricia Van Gerpen Executive Director South Dakota Public Utilities Commission Capitol Building, 1st floor 500 East Capitol Avenue Pierre, SD 57501-5070 Re: In the Matter of Otter Tail Power Company’s Transmission Cost Recovery Rider Filing,

Docket No. EL10-015. Dear Ms. Van Gerpen:

Enclosed please find the revised petition of Otter Tail Power Company, to the South Dakota Public Utilities Commission on implementation of a transmission cost recovery rider pursuant to Statutes §49-34A-25.1 through §49-34A-25.4. The initial petition was filed on November 5, 2010. Errors were discovered in the body of the original petition and Otter Tail is submitting this revised petition to correct the errors. The attachments included with the original petition are still valid, and have been included with the revised petition for convenience. If you have any questions regarding this filing, please contact me at 218-739-8269 or [email protected]. Sincerely, /s/ BRYAN D. MORLOCK Bryan D. Morlock, P.E. Consultant, Planning wao Enclosures By electronic filing

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STATE OF SOUTH DAKOTA BEFORE THE

SOUTH DAKOTA PUBLIC UTILITIES COMMISSION _____________________________ Docket No. __________ In the Matter of Otter Tail Power Company ’s Petition to Establish a Transmission Cost Recovery Tariff _____________________________

REVISED PETITION OF OTTER TAIL POWER COMPANY

I. INTRODUCTION.

Otter Tail Power Company, (“Otter Tail or Company”), hereby petitions the South

Dakota Public Utilities Commission (“Commission”) for approval of a Transmission Cost

Recovery Tariff, pursuant to SDCL Chapter 49-34A Sections 25.1 through 25.4.

II. GENERAL FILING INFORMATION.

A. Name, address, and telephone number of the utility making the filing.

Otter Tail Power Company 215 South Cascade Street P.O. Box 496 Fergus Falls, MN 56538-0496 Phone (218) 739-8200

B. Name, address, and telephone number of the attorney for Otter Tail.

Bruce Gerhardson Associate General Counsel Otter Tail Power Company 215 South Cascade Street P.O. Box 496 Fergus Falls, MN 56538-0496 Phone (218) 998-7108 Fax (218) 998-3165

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C. Title of utility employee responsible for filing.

Bryan D. Morlock, P.E. Consultant, Planning Otter Tail Power Company 215 South Cascade Street P.O. Box 496 Fergus Falls, MN 56538-0496 (218) 739-8269 FAX (218) 739-8629

D. The date of filing and the date changes will take effect.

The date of the initial filing was November 5, 2010. The date of this revised filing is

December 21, 2010. Otter Tail proposes that the tariff mechanism for the recovery of charges

for jurisdictional costs of new or modified transmission facilities and federally regulated costs

charged to Otter Tail to increase regional transmission capacity or reliability, contained herein,

go into effect as of March 1, 2011.

E. Statute controlling schedule for processing the filing.

ARSD Part 20:10:13:15 requires a 30-day notice to the Commission of a proposed change in

a utility’s tariff schedule, after which time the proposed changes take effect unless suspended.

Because no determination of Otter Tail’s general revenue requirement is necessary, the report

called for under Part 20:10:13:26 and the general notice provisions applicable to changes in rates

is not applicable in this filing. Otter Tail requests an expedited and informal proceeding,

including any variances that may be necessary.

Pursuant to ARSD 20:10:13:18, Otter Tail will post a Notice of proposed changes

contained in Attachment #10. This Notice will be placed in a conspicuous place in each business

office in Otter Tail’s affected electric service territory in South Dakota for at least 30 days before

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the change becomes effective. Otter Tail has also included Attachment #7 to comply with ARSD

20:10:13:26, which requires the utility to report all rate schedule changes and customer impacts.

III. BACKGROUND OF ISSUE.

The South Dakota Legislature in 2006 passed HB 1091 which authorizes the Commission to

approve a tariff mechanism for the automatic annual adjustment of charges for a public utility to

recover the South Dakota jurisdictional portion of eligible investments in and expenses related to

new or modified transmission resources. Eligible projects are defined as new or modified

transmission facilities more than 5 miles in length and rated at 34.5 kilovolts or more.

Associated facilities such as transformers and substations are included.

HB 1091 is the Legislature’s instrument to incentivize the investment in new

transmission facilities to improve the capability and stability of the electric transmission system

in South Dakota.

IV. PROPOSED CHANGES.

During the 2006 South Dakota Legislative Session, SD Stat. §§49-34A-25.1 through 49-

34A-25.4 were amended to read as follows:

49-34A-25.1. Approval of tariff mechanisms for automatic annual adjustment of charges for

jurisdictional costs of new or modified transmission facilities. Notwithstanding any other

provision of this chapter, the commission may approve a tariff mechanism for the automatic

annual adjustment of charges for the jurisdictional costs of new or modified transmission

facilities with a design capacity of thirty-four and one-half kilovolts or more and which are

more than five miles in length. For the purposes of §§49-34A-25.1 to 49-34A-25.4, inclusive,

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electric transmission facilities and electric transmission lines covered by this section include

associated facilities such as substations and transformers.

49-34A-25.2. Approval, rejection, or modification of certain tariffs—Notice and hearing.

Upon filing of an application consistent with rules promulgated by the commission by any

public utility providing transmission service, the commission may approve, reject, or modify,

after notice, hearing, and comment, a tariff that:

(1) Allows the public utility to recover on a timely basis the costs net of revenues of

facilities described in §49-34A-25.1;

(2) Allows a return on investment at the level approved in the public utility’s last general

rate case, unless a different return is found to be consistent with the public interest;

(3) Provides a current return on construction work in progress, if the recovery from

retail customers for the allowance for funds used during construction is not sought

through any other mechanism;

(4) Allocates project costs appropriately between wholesale and retail customers; and

(5) Terminates recovery once costs have been fully recovered or have otherwise been

reflected in the public utility’s general rates.

49-34A-25.3. Filing for annual rate adjustments—Contents. A public utility may file annual

rate adjustments to be applied to customer bills paid under the tariff approved pursuant to

§49-34A-25.2. In the utility’s filing, the pubic utility shall provide:

(1) A description of and context for the facilities included for recovery;

(2) A schedule for implementation of applicable projects;

(3) The public utility’s costs for these projects;

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(4) A description of the public utility’s efforts to ensure the lowest reasonable costs to

ratepayers for the project; and

(5) Calculations to establish that the rate adjustment is consistent with the terms of the

tariff established in §49-34A-25.2.

49-34A-25.4. Standards for approval of annual rate adjustments. Upon receiving a filing

under §49-34A-25.3 for a rate adjustment pursuant to the tariff established in §49-34A-25.2,

the commission shall approve the annual rate adjustments if, after notice, hearing, and

comment, the costs included for recovery through the tariff were or are expected to be

prudently incurred and achieve transmission system improvements at the lowest reasonable

cost to ratepayers.

In this petition, Otter Tail is proposing to implement a rate schedule (“Transmission Rider”)

for the recovery of investments and expenses associated with new or modified transmission

projects that are not included in base rates, and for the recovery of expenses or charges from the

Midwest Independent Transmission System Operator (MISO) through Schedule 26 under the

federally regulated MISO Open Access Transmission, Energy, and Operating Reserve Markets

Tariff.

a. Midwest ISO Regional Expansion Criteria and Benefits (“RECB”) charges (“MISO Schedule 26”)

Otter Tail incurs charges from the Midwest ISO to pay for a portion of transmission

investments of other electric utilities pursuant to Attachment FF of the Midwest ISO’s Open

Access Transmission, Energy, and Operating Reserve Markets Tariff (“Tariff”). Attachment FF

specifies the cost allocation procedures for new transmission projects within the Midwest ISO.

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This cost allocation, oftentimes referred to as “RECB,” (after the Regional Expansion Criteria

and Benefits Task Force (“RECB”) stakeholder committee) specifies the process in which the

Midwest ISO identifies and evaluates new transmission expansion projects eligible for inclusion

in the Midwest ISO Transmission Expansion Plan (“MTEP”). The MTEP issued by the Midwest

ISO is a regional expansion plan with three primary objectives: 1) to perform a reliability

assessment of the Midwest ISO integrated transmission system; 2) to review transmission

owning members’ transmission plans and make sure that appropriate projects are reviewed and

recommended to Midwest ISO Board of Directors for approval; and 3) to develop transmission

upgrades to improve market performance.

Through its MTEP process, the Midwest ISO determines whether a proposed

transmission project is eligible for cost-sharing pursuant to Attachment FF of the Midwest ISO

Open Access Transmission, Energy and Operating Reserve Markets Tariff (“Tariff”). There are

a variety of project types under the Midwest ISO Tariff that are eligible for cost-sharing

including the following: (1) Baseline Reliability Project (“BRP”) required to ensure

Transmission System reliability consistent with North American Electric Reliability Corporation

(“NERC”) standards, (2) Regionally Beneficial Project (“RBP”) that provides economic benefit

to the Midwest ISO Transmission System, (3) Generator Interconnection Project (“GIP”)

Network Upgrades required for the interconnection of generation to the Midwest ISO

Transmission System, or (4) Multi Value Project (“MVP”) that address regional public policy,

reliability, and economic value to the Midwest ISO footprint.

Baseline Reliability Projects that are 345 kV and greater and that have a project cost

greater than $5 million (or 5 percent or more of the Transmission Owner’s net transmission

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plant) will be allocated 20 percent on a system-wide (postage stamp) rate to all Midwest ISO

Transmission Customers, with the remaining 80 percent allocated on a sub-regional basis, which

is based on a system power flow analysis referred to as Line Outage Distribution Factor

(“LODF”).1 Baseline Reliability Projects that are between 100 kV and 345 kV and have a project

cost greater than $5 million in project costs (or 5% or more of the Transmission Owner’s net

transmission plant) will be allocated 100 percent on a sub-regional (“LODF”) basis to all

Transmission Customers in designated pricing zones.

Regionally Beneficial Projects that have a project cost greater than $5 million will be

allocated 20 percent on a system-wide (postage stamp) rate to all Midwest ISO Transmission

Customers and 80 percent will be allocated to each pricing zone within each of three Planning

Sub Regions (West, Central, and East) based on the relative benefit determined for each Planning

Sub Region that has a positive present value of annual benefits over the evaluation period using

the methodology for project benefit determined pursuant to Section II.B.1 of Attachment FF to

the Midwest ISO Tariff.

Generator Interconnection Project Network Upgrades (“GIP NUs”) are allocated pursuant

to Attachment FF of the Midwest ISO Tariff, assigning up to 100 percent of the cost

responsibility for Network Upgrades associated with GIPs to be allocated to the Interconnection

Customer. For Network Upgrades to facilities in voltage classes at or above 345 kV, the

1 LODF is an engineering calculation of the change of flows on the Transmission System created by

the addition of a new transmission facility. MISO uses computer software to measure and model the LODF of all facilities within the MISO Transmission System for each new facility added to the system. MISO then models the LODF for each pricing zone for each new transmission facility. LODF is used because it is considered by MISO planners as a way to determine the added benefit of a new transmission facility to each of the pricing zones. Generally, pricing zones in close proximity to the proposed transmission facility have the greatest LODF cost allocation and those furthest away have little to no cost allocation from the LODF method, thus this benefit assignment is defined as Sub-Regional.

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Interconnection Customer shall be repaid 10 percent of the costs of the Generation

Interconnection Project funded by the interconnection Customer once Commercial Operation is

achieved. The 10 percent reimbursement is recovered from all Transmission Customers in the

Midwest ISO on a postage stamp basis. Network Upgrades to facilities in voltage classes below

345 kV are assigned 100% to the Interconnection Customer.

Multi Value Projects are a new project classification generally planned as regional

transmission that provides multiple benefits. This project classification and its cost allocation are

currently pending before FERC in Docket No. ER10-1791. As proposed, the Multi Value

Project is a transmission expansion project that (1) enables the Transmission System to reliably

and economically deliver energy in support of documented energy policy mandates or laws that

have been enacted or adopted through state or federal legislation or regulatory requirement or (2)

provides multiple types of economic value across multiple pricing zones with a Total MVP

Benefit-to-Cost ratio of 1.0 or higher, or (3) solves at least one projected violation of a NERC or

Regional Entity standard and provides economic value across multiple pricing zones, which

collectively generates total financially quantifiable benefits in excess of the total project costs.

The costs of an approved MVP project shall be recovered from all load in, and exports from, the

Midwest ISO footprint on a postage-stamp basis based on system usage (i.e. MWh).

If, through the MTEP eligibility screening process, a project does not meet the criteria for

a BRP, RBP, GIP NU, or MVP but is determined to provide local benefits the assignment of

costs for that facility is left to the local pricing zone of the transmission owner of the facility.

For example, for a proposed transmission facility that primarily benefits a local load center, the

Midwest ISO would not administer cost sharing provisions under Attachment FF and the local

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transmission owner would be solely bear those costs and recover its revenue requirement under

Attachment O to the Midwest ISO Tariff.

The BRP, RBP, GIP NU, and MVP cost allocation criteria and recovery mechanisms are

specified in detail in Attachment FF,2 Attachment GG,3 and Schedule 264 of the Midwest ISO

Tariff. The Midwest ISO’s annual MTEP review process identifies those transmission projects

that will be included in “Appendix A” to the MTEP and the respective cost-sharing is identified

for each project as applicable.

The allocation of some project costs to MISO participants on a broader scale than just the

utilities or companies that invest in the transmission project means that project investment on an

individual company basis is unlikely to match the level of allocation on a load share ratio. In

fact, each project which has a system-wide cost allocation would need to have every MISO entity

with a cost allocation also be an investment participant in the project at the same level or the

project would be underfunded and not be constructed. The alternative is that some project

investors must invest in projects at a level that exceeds their cost allocation.

Otter Tail proposes to use the following methodology for cost recovery of transmission

projects:

• For a project which does not meet the criteria for a BRP, RBP, GIP NU, or MVP

designation but is determined to provide local benefits and thus the assignment of costs

for that facility is left to the local pricing zone of the transmission owner of the facility,

Otter Tail will use the Transmission Rider for cost recovery until the project is included

in base rates or has been fully recovered. Revenue credits associated with wholesale use 2 Attachment FF specifies the Transmission Expansion Planning Protocols. 3 Attachment GG specifies the calculation of the Network Upgrade Charge. 4 Schedule 26 specifies the Network Upgrade Charge from Transmission Expansion Plan.

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of the project will be received for the project through the Attachment O process as

discussed below.

• For a project which does meet the criteria for a BRP, RBP, GIP NU, or MVP designation

with MISO determined cost allocations on a regional or system-wide basis, Otter Tail

will allow those projects to remain in Attachment GG and to collect the revenue

requirements through the Attachment GG and Schedule 26 process. This will shield

Otter Tail customers from revenue requirements of the project except for the revenue

requirements specifically allocated to Otter Tail retail customers through the MISO

process. Retail customers will already have received the benefit of the wholesale level

usage of the project by other entities that received a cost allocation and the Schedule 26

revenue received by Otter Tail will provide the project revenue requirements to pay for

project costs.

Otter Tail has included Schedule 26 costs for recovery in this filing. The costs appear on

line 4 of the Tracker Account (Attachment 4) and are shown separately in Attachment #9.

b. New or Modified Transmission Projects

Otter Tail presently has a general rate case filed with the Commission in Docket No.

EL10-011. All Otter Tail transmission projects for which the Company is seeking cost recovery

are included in the rate case and are anticipated to be included in base rates. Otter Tail does not

have any transmission projects in its current 5-year capital budget for which it plans to seek cost

recovery through the Transmission Rider.

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Attachments #5 and #6 are examples of revenue requirement calculations for

transmission projects included in the Transmission Rider. The revenue requirement for a project

included in the Transmission Rider will include several components as described below.

• Rate base section. This section provides details on the amount of plant in service,

accumulated depreciation, construction work in progress (CWIP) (if applicable),

accumulated deferred taxes, and includes a 13-month average rate base calculation.

• CWIP. SDCL §49-34A-25.2 allows a current return on CWIP.

• Expense section. The expenses applicable to a project will be listed here and include

operating costs, property taxes, depreciation, and, income taxes.

• Revenue requirements section. This section will show the components of the revenue

requirements. Included are the items computed from the sections previously mentioned,

including expenses and return on rate base. Adjustments (usually reductions) to the

revenue requirement will be included for monies received or paid for non-retail use of the

lines. This includes amounts of MISO revenues generated from the open access

transmission tariff. It is a revenue credit that represents revenue that Otter Tail receives

for the wholesale use of its transmission system from MISO and other non-MISO users.

The revenue credit is a percentage of the revenue requirement based on the prior year’s

actual revenue credits divided by the most recent non-levelized revenue requirements

from the MISO formula rate shown in MISO Attachment O. Using the information from

Otter Tail’s 2011 Attachment O, the revenue credit adjustment is 17.32 percent. This

MISO revenue credit percentage is applied to in-service revenue requirements and

updated each year thereafter. Therefore, the 17.32 percent is applied to the computed

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revenue requirement for the project. The calculation of the revenue credit adjustment is

shown in Attachment #8.

• Return on investment (cost of capital). The return on investment will utilize the cost of

capital determined in the most recent approved general rate case.

• Depreciation expense. Depreciation expense will be calculated using the company’s

latest transmission composite depreciation rate.

• Property taxes. The property tax calculation will be based on Otter Tail’s composite tax

rate for the jurisdiction in which the transmission facilities are located, and will be

calculated in accordance with the procedures specified by that state.

• O&M Expense. Annual operation and maintenance (O&M) expense of the transmission

lines typically will include costs related to line patrol and inspections, vegetation

management, small repair items, storm restoration, and supervision of this work.

Scheduled transmission line patrols are typically done once every other year on single

pole 115 kV lines. Unscheduled patrols are completed for line sections where an

unexplained interruption has occurred. To reduce costs of patrol after an interruption,

data from protective relays are used to limit the patrol area. Vegetation management of

new lines is typically limited for the first five years since our construction standard is to

remove as many trees as possible and leave low growing brush. After five years,

vegetation management is completed based on information gathered during line patrols.

Other O&M costs are dependent on the severity of storms and resulting damage, tree

growth, items found on line patrols, the cost of NERC reporting requirements, and

supervision. Otter Tail will set up transmission O&M accounting projects to track O&M

costs specifically related to each line included in the Rider.

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c. Tracker Balance

Otter Tail maintains a tracker account worksheet and accounting system to track and

account for retail revenue requirements until all costs have been fully recovered or reflected in

base rates as the result of a general rate case. The tracker account information compares Otter

Tail’s costs and the amount recovered through South Dakota retail revenue. The tracker account

balance (either positive or negative) will accrue monthly carrying charges at a rate of 1/12 of

Otter Tail’s cost of capital times the tracker balance. Carrying charges on a negative tracker

balance will accrue to the benefit of retail customers and carrying charges on a positive tracker

balance will accrue to Otter Tail.

Otter Tail anticipates continuing to make annual filings to revise the Transmission Cost

Recovery Rates to reflect updated revenue requirements and additional new transmission

projects. When submitting annual filings, the tracker account will be updated so that any over-

or under-recovered amount at the end of the previous year will be reflected in the Transmission

Rider adjustment for the upcoming year. Tracker Account detail is included in Attachment 4.

V. RATE DESIGN.

Otter Tail’s proposed rate design uses the transmission demand allocation factor, D2,

from Otter Tail’s last South Dakota general rate case to allocate total revenue requirements to

jurisdictions (South Dakota, 9.260463 percent) and rate classes. Otter Tail will update this

allocator once Otter Tail’s pending general rate case is completed and reflect any adjustment in

the proposed tracker. The large general service (LGS) class’s portion of retail revenue

requirements based on D2 is 47.54 percent. The remaining portion (52.46 percent) of the retail

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revenue requirements will be collected from the non-LGS rate classes. This allocation method

appropriately reflects the demand-driven nature of transmission costs. Otter Tail’s proposed

LGS rate design for the Transmission Rider incorporates demand ($/kW-month) and energy

(¢/kWh) rates that recover the transmission project costs in a manner that follows existing LGS

base rate design. Specifically, the LGS revenue requirements will be split between demand and

energy based on the 2011 forecast base rate demand and energy revenue proportion of

approximately 14 percent demand and 86 percent energy. As part of future filings, this split will

be reviewed as necessary to reflect any material load changes. The LGS demand rate will be

calculated as the LGS demand revenue requirements divided by the LGS class billing demand

for the forecast year. The LGS energy rate will be calculated as the LGS energy revenue

requirements divided by the LGS kilowatt-hour sales for the projected calendar year.

For the remaining retail rate classes (non-LGS) of controlled service, and lighting, and all

other classes, Otter Tail proposes an energy rate only. A rate for each class is a separate energy-

based (kWh) change calculated as the revenue requirements divided by the kilowatt-hour sales

for the projected period. This rate design for controlled service, lighting, and all other classes is

appropriate because it reflects the primarily energy-based rates for these classes and reduces the

complexisty of administration.

VI. RATE APPLICATION AND IMPACT.

Otter Tail proposes that the Transmission Rider should be applicable to electric service

under all of Otter Tail’s retail rate schedules. The charge will be included as part of the Fuel

Adjustment line on customers’ bills. The proposed rates are as follows:

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Class ¢ / kWh $ / kW Large General Service 0.045¢ $0.039 Controlled Service 0.061¢ N/A Lighting 0.067¢ N/A All other service 0.043¢ N/A

The following table shows the estimated rate impact by retail customer class.

Approved SD Rates Based on 2007 Test Year

Rate Class Impacts (1) Rate Class Impacts (1) Residential Outdoor Lighting Average Rate (¢/kWh) 8.416 Average Rate (¢/kWh) 13.137Increase % 0.52% Increase % 0.55%Average Impact ($/month) $0.35 Average Impact ($/month) $0.05

Farm Municipal Pumping Average Rate (¢/kWh) 7.797 Average Rate (¢/kWh) 5.892Increase % 0.60% Increase % 0.72%Average Impact ($/month) $0.81 Average Impact ($/month) $1.49

General Service Water Heating, Controlled Average Rate (¢/kWh) 7.857 Average Rate (¢/kWh) 6.465Increase % 0.53% Increase % 1.06%Average Impact ($/month) $1.13 Average Impact ($/month) $0.13

Large General Service Interruptible Load Average Rate (¢/kWh) 5.484 Average Rate (¢/kWh) 3.929Average Rate ($/kW) $4.30 Increase % 1.66%Increase % 1.00% Average Impact ($/month) $1.10Average Impact ($/month) $117.96

Irrigation Deferred Load Average Rate (¢/kWh) 6.470 Average Rate (¢/kWh) 4.245Increase % 0.67% Increase % 1.37%Average Impact ($/month) $2.42 Average Impact ($/month) $0.90(1) Average rate calculation is from SD Docket No. EL08-030. Rate impacts are calculated from base rates.

The above rates are based on the assumption that they will be in effect beginning March

1, 2011. Revenue requirement calculations are based on the total 2011 costs, assuming revenue

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collection over the entire year. With revenue collection only over the March 1 – December 31,

2011 time period, some 2011 revenue requirements will be carried over to 2012 through the

tracker true-up process. It is estimated that approximately $46,757 of revenue requirements plus

$3,538 of carrying cost will be carried into 2012. If the effective date is significantly later than

March 1, 2011, Otter Tail requests the option to recalculate the Transmission Cost Recovery

Rates in order to recover all approved costs in the remainder of 2011.

VII. TRANSMISSION COST RECOVERY RIDER RATE SCHEDULE.

Otter Tail’s proposed Transmission Cost Recovery Rider is Attachment #7 to this

Petition.

VIII. REVISIONS TO OTHER RATE SCHEDULES.

Attachment #7 to this Petition also includes redline and proposed final versions of Otter

Tail’s Rate Schedules Index and Rate Schedule 13.00, Mandatory Riders – Applicability Matrix,

showing the addition of the Transmission Cost Recovery Rider.

IX. FIVE-YEAR TRANSMISSION RIDER ESTIMATE.

Otter Tail does not have any transmission projects in the five-year capital budget at this

time that would be included in the Transmission Rider for ratebase recovery. It is possible that a

project or projects could arise within the five-year period due to customer needs or unforeseen

circumstances.

It is very difficult to forecast the Schedule 26 charges as MISO does not provide the

information necessary to develop forward projections. Thus Otter Tail cannot forecast the

Schedule 26 charges from RECB projects being constructed in other parts of MISO. Based on

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the Company’s expected investment levels in the Fargo to St. Cloud and Bemidji to Grand

Rapids CAPX2020 projects, Otter Tail is forecasting the following Company-wide Schedule 26

charges:

2011 $1,218,960 2012 $4,840,000 2013 $6,828,000 2014 $8,223,000 2015 $9,045,000

X. CONCLUSION.

For the foregoing reasons, Otter Tail respectfully requests approval to implement the rate

schedule with Rate Designation 13.05 effective as of March 1, 2011.

Date: December 21, 2010 Respectfully submitted:

OTTER TAIL POWER COMPANY,

___________________________

Bryan D. Morlock, P.E. Consultant, Planning 215 South Cascade Street P.O. Box 496 Fergus Falls, MN 56538-0496 Phone (218) 739-8269

Bruce Gerhardson Associate General Counsel Otter Tail Power Company 215 South Cascade Street P. O. Box 496 Fergus Falls, MN 56538-0496 (218) 998-7108

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Attachments Attachment #1 Revenue

Attachment #2 Revenue Requirements Summary

Attachment #3 Rate Design

Attachment #4 Tracker Summary

Attachment #5 Transmission Project #1 Example Revenue Requirements Calculation

Attachment #6 Transmission Project #2 Example Revenue Requirements Calculation

Attachment #7 Redline and Clean Rate Schedules

Attachment #8 Wholesale Sales Revenue Credit Worksheet

Attachment #9 MISO Schedule 26 Expense Estimate

Attachment #10 Customer Notice

Otter Tail Power Company Attachment 1Transmission Cost Recovery Rider Page 1 of 1Docket No. EL10-___

Projected Revenue for 2011

Class Units Rate per Unit Amount

Large General Service (a) 376,715 kW $0.039 $14,791200,751,529 kWh 0.045 ¢ 90,858

Total LGS $105,648

Controlled service (b) 43,875,465 kWh 0.061 ¢ $26,846

Lighting (c) 4,509,929 kWh 0.067 ¢ 3,034

All other service 201,185,118 kWh 0.043 ¢ 86,722

Total revenue $222,251

(a)(b)

(c)

Rate Schedules 10.03 Large General Service and 10.05 Large General Service - Time of DayRate Schedules 14.01 Water Heating, 14.04 Interruptible Load (CT Metering), 14.05 Interruptible Load (Self-Contained Metering), 14.06 Deferred LoadRate Schedules 11.03 Outdoor Lighting (energy only), 11.04 Outdoor Lighting


Summary of Revenue Requirements

Revenue Requirements 2011

Project 1 -$

Project 2 -

Schedule 26 222,251

2010 Carrying cost -

2010 True Up -

Total 222,251$


Class Allocation and Rate Design

2011

Total South Dakota revenue requirements $222,251 *

Large General Service class 47.54% $105,648Controlled service 12.08% 26,846Lighting 1.37% 3,034All other service 39.02% 86,722

Total $222,251

Large General Service class kW 376,715 Large General Service class kWh 200,751,529

Controlled service kWh 43,875,465 Lighting kWh 4,509,929 All other service kWh 201,185,118

Large General Service class $ / kW month 0.039 **Large General Service class cents / kwh 0.045

Controlled service cents / kwh 0.061 Lighting cents / kwh 0.067 All other service cents / kwh 0.043

** LGS revenue is 14% demand and 86% energy

* Jurisdictional transmission allocation factor (D2 = 9.260463%) is from Otter Tail's last general rate case in South Dakota.

Otter Tail Power CompanyTransmission Rider Tracker PAGE 1 0F 1South Dakota

TRACKER SUMMARYLine January February March April May June July August September October November December YE

Requirements Compared to Billed: Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected ProjectedRevenue Requirements ck

1 Project 1 0 0 0 0 0 0 0 0 0 0 0 0 02 Project 2 0 0 0 0 0 0 0 0 0 0 0 0 03 Total 0 0 0 0 0 0 0 0 0 0 0 0 04 MISO Schedule 26 - expense/(revenue) 20,385 20,659 22,164 19,617 19,250 14,994 17,380 18,022 18,986 18,925 15,380 16,490 222,2515 Net Revenue Requirement 20,385 20,659 22,164 19,617 19,250 14,994 17,380 18,022 18,986 18,925 15,380 16,490 222,25167 Billed (forecast kWh x adj factor) 0 0 19,894 18,481 16,519 16,564 17,035 17,347 17,533 16,552 18,481 20,256 222,251 89 Difference 20,385 20,659 2,411 1,423 3,036 (1,253) 685 1,008 1,795 2,723 (2,736) (3,379) (3,379)

10 Carrying Charge - 142 286 305 317 340 334 341 350 365 387 370 11 Cummulative Difference 20,385 41,186 43,883 45,611 48,964 48,051 49,070 50,419 52,564 55,653 53,303 50,295 50,295 1213 Carrying Charge Calculation 0 142 286 305 317 340 334 341 350 365 387 37014 Cumulative Carrying Charge 0 142 428 733 1,050 1,390 1,724 2,065 2,416 2,781 3,168 3,538 3,53815 Carrying cost 8.34% 8.34% 8.34% 8.34% 8.34% 8.34% 8.34% 8.34% 8.34% 8.34% 8.34% 8.34% 8.34%16 Monthly Rate 0.695000% 0.695000% 0.695000% 0.695000% 0.695000% 0.695000% 0.695000% 0.695000% 0.695000% 0.695000% 0.695000% 0.695000%171819202122 Forecasted Sales (MWh) 44,366 43,953 40,309 37,446 33,471 33,561 34,516 35,149 35,525 33,537 37,446 41,043 450,322 23 450,322 2425

SUMMARYSUMMARY Year 2011

Revenue requirements $222,251Revenue requirements 2011 $222,2512010 Carrying Charge and True up 0 True up & Carrying Charge 0Total requirements $222,251 Total requirements $222,2512011 projected sales in mWh 450,322 2011 projected sales in mWh 450,322 Average Rate $0.00049 Average Rate $0.00049

ATTACHMENT 4

2011

ATTACHMENT 5 Page 1 of 2

Otter Tail Power CompanyTransmission Rider - Revenue RequirementsProject:

Year>> 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Total

Line January February March April May June July August September October November December 20111 RATE BASE2 Plant Balance 0 0 0 0 0 0 0 0 0 0 0 0 03 Accumulated. Depreciation 0 0 0 0 0 0 0 0 0 0 0 0 04 Net Plant in Service 0 0 0 0 0 0 0 0 0 0 0 0 05 CWIP 0 0 0 0 0 0 0 0 0 0 0 0 06 Accum. Deferred Inc. Taxes Fed & State 0 0 0 0 0 0 0 0 0 0 0 0 07 Ending rate base 0 0 0 0 0 0 0 0 0 0 0 0 089 Average rate base (Informational only; no impact) - 0 0 0 0 0 0 0 0 0 0 0 0 01011 Return on Rate Base 0 0 0 0 0 0 0 0 0 0 0 0 01213 Available for return (equity portion of rate base) 0 0 0 0 0 0 0 0 0 0 0 0 01415 EXPENSES16 O&M and Depreciation17 Operating Costs 0 0 0 0 0 0 0 0 0 0 0 0 018 Property Tax 0 0 0 0 0 0 0 0 0 0 0 0 019 Book Depreciation 0 0 0 0 0 0 0 0 0 0 0 0 020 Total O&M and Depreciation Expense 0 0 0 0 0 0 0 0 0 0 0 0 02122 Income before Taxes23 Available for return (from above) 0 0 0 0 0 0 0 0 0 0 0 0 024 Taxable Income (grossed up) 1.7056 0 0 0 0 0 0 0 0 0 0 0 0 02526 Income Taxes27 Current and Def Income Taxes 41.37% - - - - - - - - - - - - - 28 Total Income Tax Expense 0 0 0 0 0 0 0 0 0 0 0 0 0293031 REVENUE REQUIRMENTS32 Expenses 0 0 0 0 0 0 0 0 0 0 0 0 033 Return on rate base 0 0 0 0 0 0 0 0 0 0 0 0 034 Subtotal revenue requirements 0 0 0 0 0 0 0 0 0 0 0 0 035 Adjustments36 Transmission Revenue 14.99% 0 0 0 0 0 0 0 0 0 0 0 0 037 Total revenue requirements 0 0 0 0 0 0 0 0 0 0 0 0 03839 SD share - D2 factor 9.26% 0 0 0 0 0 0 0 0 0 0 0 0 0


Otter Tail Power CompanyTransmission Rider - Revenue RequirementsProject:

Year>> 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Total

Line January February March April May June July August September October November December 2011

SUPPORTING INFORMATION / DATALine1 SD Capstructure with allowed ROE per order.2 Capital Structure Ratio3 Debt 46.50%4 Preferred equity 3.50%5 Common equity 50.00%6 Total 100.00%78 Book9 Project life (years) 50 1011 Statutory Tax Rate 41.37%12 Tax conversion factor 1.70561 13 Transmission 1415 Deferred Tax16 Book depr. rate 1.9978% 0.16% 0.16% 0.16% 0.16% 0.16% 0.16% 0.16% 0.16% 0.16% 0.16% 0.16% 0.16% 2.00%17 Tax depr. rate (15-year MACRS) Yr 1 6.25% 6.25%18 Tax depr. rate (15-year MACRS) Yr 2 9.38% 9.38%19 Tax depr. rate (15-year MACRS) Yr 3 8.44% 0.70% 0.70% 0.70% 0.70% 0.70% 0.70% 0.70% 0.70% 0.70% 0.70% 0.70% 0.70% 8.44%20 Tax depr. rate (15-year MACRS) Yr 4 7.59% 7.59%21 Tax depr. rate (15-year MACRS) Yr 5 6.83% 6.83%22 Tax depr. rate (15-year MACRS) Yr 6 6.15% 6.15%23 Tax depr. rate (15-year MACRS) Yr 7 5.91% 5.91%24 Tax depr. rate (15-year MACRS) Yr 8 5.90% 5.90%25 Tax depr. rate (15-year MACRS) Yr 9 5.91% 5.91%26 Tax depr. rate (15-year MACRS) Yr 10 5.90% 5.90%27 Tax depr. rate (15-year MACRS) Yr 11 5.91% 5.91%28 Tax depr. rate (15-year MACRS) Yr 12 5.90% 5.90%29 Tax depr. rate (15-year MACRS) Yr 13 5.91% 5.91%30 Tax depr. rate (15-year MACRS) Yr 14 5.90% 5.90%31 Tax depr. rate (15-year MACRS) Yr 15 5.91% 5.91%32 Tax depr. rate (15-year MACRS) Yr 16 2.21% 2.21%3334 Book depreciation 0 0 0 0 0 0 0 0 0 0 0 0 0 035 Tax depreciation 0 0 0 0 0 0 0 0 0 0 0 0 0 036 Book vs. tax depreciation 0 0 0 0 0 0 0 0 0 0 0 0 0 037 Federal & State deferred income taxes 41.37% 0 0 0 0 0 0 0 0 0 0 0 0 0 038


Otter Tail Power CompanyTransmission Rider - Revenue Requirements lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr:Langdon-Hensel Line Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation:

TotalYear>> 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 3

Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected ProjectedLine January February March April May June July August September October November December 20111 RATE BASE2 Plant Balance 0 0 0 0 0 0 0 0 0 0 0 0 03 Accumulated. Depreciation 0 0 0 0 0 0 0 0 0 0 0 0 04 Net Plant in Service 0 0 0 0 0 0 0 0 0 0 0 0 05 CWIP 0 0 0 0 0 0 0 0 0 0 0 0 06 Accum. Deferred Inc. Taxes Fed & State 0 0 0 0 0 0 0 0 0 0 0 0 07 Ending rate base 0 0 0 0 0 0 0 0 0 0 0 0 089 Average rate base - 0 0 0 0 0 0 0 0 0 0 0 0 01011 Return on Rate Base 0 0 0 0 0 0 0 0 0 0 0 0 01213 Available for return (equity portion of rate base) 0 0 0 0 0 0 0 0 0 0 0 0 01415 EXPENSES16 O&M and Depreciation17 Operating Costs 0 0 0 0 0 0 0 0 0 0 0 0 018 Property Tax 0 0 0 0 0 0 0 0 0 0 0 0 019 Book Depreciation 0 0 0 0 0 0 0 0 0 0 0 0 020 Total O&M and Depreciation Expense 0 0 0 0 0 0 0 0 0 0 0 0 02122 Income before Taxes23 Available for return (from above) 0 0 0 0 0 0 0 0 0 0 0 0 024 Taxable Income (grossed up) 1.7056 0 0 0 0 0 0 0 0 0 0 0 0 02526 Income Taxes27 Current and Def Income Taxes 41.37% - - - - - - - - - - - - - 28 Total Income Tax Expense 0 0 0 0 0 0 0 0 0 0 0 0 0293031 REVENUE REQUIRMENTS32 Expenses 0 0 0 0 0 0 0 0 0 0 0 0 033 Return on rate base 0 0 0 0 0 0 0 0 0 0 0 0 034 Subtotal revenue requirements 0 0 0 0 0 0 0 0 0 0 0 0 035 Adjustments36 Transmission Revenue 14.99% 0 0 0 0 0 0 0 0 0 0 0 0 037 Total revenue requirements 0 0 0 0 0 0 0 0 0 0 0 0 03839 South Dakota share - D2 factor 9.260463% 0 0 0 0 0 0 0 0 0 0 0 0 0


Otter Tail Power CompanyTransmission Rider - Revenue Requirements lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr: lease incr:Langdon-Hensel Line Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation: Inflation:

TotalYear>> 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 3

Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected ProjectedLine January February March April May June July August September October November December 2011

SUPPORTING INFORMATION / DATALine1 SD Capstructure with allowed ROE per order.2 Capital Structure Ratio3 Debt 46.50%4 Preferred equity 3.50%5 Common equity 50.00%6 Total 100.00%78 Book9 Project life (years) 50 1011 Statutory Tax Rate 41.37%12 Tax conversion factor 1.70561 13 Transmissio 14 D2 for pendin 15 Deferred Tax16 Book depr. rate 2.04% 0.17% 0.17% 0.17% 0.17% 0.17% 0.17% 0.17% 0.17% 0.17% 0.17% 0.17% 0.17% 2.00%17 Tax depr. rate (15-year MACRS) Yr 1 3.75% 3.75%18 Tax depr. rate (15-year MACRS) Yr 2 9.63% 9.63%19 Tax depr. rate (15-year MACRS) Yr 3 8.66% 0.72% 0.72% 0.72% 0.72% 0.72% 0.72% 0.72% 0.72% 0.72% 0.72% 0.72% 0.72% 8.66%20 Tax depr. rate (15-year MACRS) Yr 4 7.80% 7.80%21 Tax depr. rate (15-year MACRS) Yr 5 7.02% 7.02%22 Tax depr. rate (15-year MACRS) Yr 6 6.31% 6.31%23 Tax depr. rate (15-year MACRS) Yr 7 5.90% 5.90%24 Tax depr. rate (15-year MACRS) Yr 8 5.90% 5.90%25 Tax depr. rate (15-year MACRS) Yr 9 5.91% 5.91%26 Tax depr. rate (15-year MACRS) Yr 10 5.90% 5.90%27 Tax depr. rate (15-year MACRS) Yr 11 5.91% 5.91%28 Tax depr. rate (15-year MACRS) Yr 12 5.90% 5.90%29 Tax depr. rate (15-year MACRS) Yr 13 5.91% 5.91%30 Tax depr. rate (15-year MACRS) Yr 14 5.90% 5.90%31 Tax depr. rate (15-year MACRS) Yr 15 5.91% 5.91%32 Tax depr. rate (15-year MACRS) Yr 16 3.69% 3.69%3334 Book depreciation 0 0 0 0 0 0 0 0 0 0 0 0 0 035 Tax depreciation 0 0 0 0 0 0 0 0 0 0 0 0 0 036 Book vs. tax depreciation 0 0 0 0 0 0 0 0 0 0 0 0 0 037 Federal & State deferred income taxes 41.37% 0 0 0 0 0 0 0 0 0 0 0 0 0 038

Fergus Falls, Minnesota

South Dakota P.U.C. Volume IIIndex – Sheet No. 1

ELECTRIC RATE SCHEDULESouth Dakota Index

OriginalFirst Revision

SOUTH DAKOTA PUBLIC UTILITIES COMMISSION Filed on: November 5, 2010October 31, 2008 Approved by order dated: DATEJune 30, 2009 Docket No. EL08-030

Thomas Brause Bernadeen Brutlag Manager, Regulatory

ServicesVice-President, Administration

Page 1 of 5

EFFECTIVE with bills rendered on and after

March 1, 2011July 1, 2009, in South Dakota

Electric Service – South Dakota – Index Section Prior Sheet Item

1.00 GENERAL SERVICE RULES 1.01 99.9 Scope of General Rules and Regulations 1.02 99.9 Application for Service 1.03 98.3 Deposits, Guarantees and Credit Policy 1.04 98.1 Customer Connection Charge 1.05 N/A Contracts, Agreements and Sample Forms

2.00 RATE APPLICATION 2.01 N/A Assisting Customers in Rate Selection 2.02 99.9 Service Classification

3.00 CURTAILMENT OR INTERRUPTION OF SERVICE 3.01 N/A Disconnection of Service 3.02 N/A Curtailment or Interruption of Service 3.03 N/A N/A (section reserved for future use) 3.04 N/A N/A (section reserved for future use) 3.05 N/A Continuity of Service

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(Continued)




Page 2 of 5




4.00 METERING & BILLING 4.01 N/A Meter and Service Installations 4.02 N/A Meter Readings 4.03 99.9 Estimated Readings 4.04 98.4 Meter Testing 4.05 99.9 Access to Customer Premises 4.06 99.9 Establishing Demands 4.07 99.9 Monthly Billing Period and Prorated Bills 4.08 99.9 Electric Service Statement - Identification of Amounts and Meter

Reading 4.09 N/A Billing Adjustments 4.10 99.9 Payment Policy 4.11 N/A Even Monthly Payment (EMP) Plan 4.12 N/A Summary Billing Services 4.13 N/A Account History Charge 4.14 N/A Combined Metering

5.00 STANDARD INSTALLATION AND EXTENSION RULES 5.01 99.9 Extension Rules and Minimum Revenue Guarantee 5.02 N/A Special Facilities 5.03 N/A Temporary Services 5.04 N/A Standard Installation 5.05 N/A Service Connection

6.00 USE OF SERVICE RULES 6.01 N/A Customer Equipment 6.02 99.9 Use of Service; Prohibition on Resale

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(Continued)




Page 3 of 5




7.00 COMPANY’S RIGHTS 7.01 99.9 Waiver of Rights or Default 7.02 N/A Modification of Rates, Rules and Regulations

8.00 GLOSSARY AND SYMBOLS 8.01 N/A Glossary 8.02 N/A Definition of Symbols

Rate Schedules & Riders

9.00 RESIDENTIAL AND FARM SERVICES 9.01 1 Residential Service 9.02 5 Residential Demand Control Service 9.03 16 Farm Service

10.00 GENERAL SERVICES 10.01 N/A Small General Service (Less than 20kW) 10.02 20 General Service (20kW or Greater) 10.03 30 Large General Service 10.04 N/A Commercial Service – Time of Use 10.05 30.3 Large General Service – Time of Day

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(Continued)




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11.00 OTHER SERVICES 11.01 71.3 Standby Service 11.02 90 Irrigation Service 11.03 93 Outdoor Lighting – Energy Only 11.04 94 Outdoor Lighting 11.05 95 Municipal Pumping Service 11.06 96 Civil Defense – Fire Sirens

12.00 POWER PRODUCER RIDERS & APPLICABILITY MATRIX 12.01 70.8 Small Power Producer Rider – Occasional Delivery Energy

Service 12.02 70.9 Small Power Producer Rider – Temperature-Time of Delivery

Energy Service 12.03 71 Small Power Producer Rider – Dependable Service

13.00 MANDATORY RIDERS & APPLICABILITY MATRIX 13.01 98 Fuel Adjustment Clause Rider

• Applicable to all services and riders unless otherwise stated in the mandatory riders matrix

13.02 N/A N/A (reserved for future use) 13.03 N/A N/A (reserved for future use) 13.04 98.3 Energy Efficiency Project (EEP) Rider 13.05 N/A Transmission Cost Recovery Rider

N

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(Continued)




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14.00 VOLUNTARY RIDERS & APPLICABILITY MATRIX 14.01 7 Water Heating – Controlled Service 14.02 N/A Real Time Pricing Rider 14.03 30.9 Large General Service Rider 14.04 50 Controlled Service – Interruptible Load (CT Metering) Rider 14.05 50.1 Controlled Service – Interruptible Load (Self-Continaed

Metering) Rider 14.06 50.2 Controlled Service – Deferred Load Rider 14.07 50.3

50.4 50.5

Fixed Time of Delivery Rider

14.08 94.5 Voluntary Air Conditioning Control Rider (CoolSavings) 14.09 91.5 Voluntary Renewable Energy Rider (TailWinds) 14.10 N/A N/A (section reserved for future use) 14.11 91 Released Energy Access Program (REAP) Rider 14.12 50.7 Bulk Interruptible Service Application and Pricing Guide

15.00 COMMUNITIES SERVED 15.00 N/A South Dakota Communities Served

16.00 SUMMARY OF CONTRACTS WITH DEVIATIONS 16.00 Section 4,

Sheets 1-4 Summary of Contracts with Deviations

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First Revision

SOUTH DAKOTA PUBLIC UTILITIES COMMISSION Filed on: November 5, 2010 Approved by order dated: DATE Docket No. EL08-030

Thomas BrauseVice-President, Administration

Page 1 of 5


March 1, 2011, in South Dakota


1.00 GENERAL SERVICE RULES 1.01 99.9 Scope of General Rules and Regulations 1.02 99.9 Application for Service 1.03 98.3 Deposits, Guarantees and Credit Policy 1.04 98.1 Customer Connection Charge 1.05 N/A Contracts, Agreements and Sample Forms

2.00 RATE APPLICATION 2.01 N/A Assisting Customers in Rate Selection 2.02 99.9 Service Classification

3.00 CURTAILMENT OR INTERRUPTION OF SERVICE 3.01 N/A Disconnection of Service 3.02 N/A Curtailment or Interruption of Service 3.03 N/A N/A (section reserved for future use) 3.04 N/A N/A (section reserved for future use) 3.05 N/A Continuity of Service

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First Revision

(Continued)



Page 2 of 5




4.00 METERING & BILLING 4.01 N/A Meter and Service Installations 4.02 N/A Meter Readings 4.03 99.9 Estimated Readings 4.04 98.4 Meter Testing 4.05 99.9 Access to Customer Premises 4.06 99.9 Establishing Demands 4.07 99.9 Monthly Billing Period and Prorated Bills 4.08 99.9 Electric Service Statement - Identification of Amounts and Meter

Reading 4.09 N/A Billing Adjustments 4.10 99.9 Payment Policy 4.11 N/A Even Monthly Payment (EMP) Plan 4.12 N/A Summary Billing Services 4.13 N/A Account History Charge 4.14 N/A Combined Metering

5.00 STANDARD INSTALLATION AND EXTENSION RULES 5.01 99.9 Extension Rules and Minimum Revenue Guarantee 5.02 N/A Special Facilities 5.03 N/A Temporary Services 5.04 N/A Standard Installation 5.05 N/A Service Connection

6.00 USE OF SERVICE RULES 6.01 N/A Customer Equipment 6.02 99.9 Use of Service; Prohibition on Resale

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First Revision

(Continued)



Page 3 of 5




7.00 COMPANY’S RIGHTS 7.01 99.9 Waiver of Rights or Default 7.02 N/A Modification of Rates, Rules and Regulations

8.00 GLOSSARY AND SYMBOLS 8.01 N/A Glossary 8.02 N/A Definition of Symbols

Rate Schedules & Riders

9.00 RESIDENTIAL AND FARM SERVICES 9.01 1 Residential Service 9.02 5 Residential Demand Control Service 9.03 16 Farm Service

10.00 GENERAL SERVICES 10.01 N/A Small General Service (Less than 20kW) 10.02 20 General Service (20kW or Greater) 10.03 30 Large General Service 10.04 N/A Commercial Service – Time of Use 10.05 30.3 Large General Service – Time of Day

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(Continued)



Page 4 of 5




11.00 OTHER SERVICES 11.01 71.3 Standby Service 11.02 90 Irrigation Service 11.03 93 Outdoor Lighting – Energy Only 11.04 94 Outdoor Lighting 11.05 95 Municipal Pumping Service 11.06 96 Civil Defense – Fire Sirens

12.00 POWER PRODUCER RIDERS & APPLICABILITY MATRIX 12.01 70.8 Small Power Producer Rider – Occasional Delivery Energy

Service 12.02 70.9 Small Power Producer Rider – Temperature-Time of Delivery

Energy Service 12.03 71 Small Power Producer Rider – Dependable Service

13.00 MANDATORY RIDERS & APPLICABILITY MATRIX 13.01 98 Fuel Adjustment Clause Rider

• Applicable to all services and riders unless otherwise stated in the mandatory riders matrix

13.02 N/A N/A (reserved for future use) 13.03 N/A N/A (reserved for future use) 13.04 98.3 Energy Efficiency Project (EEP) Rider 13.05 N/A Transmission Cost Recovery Rider

N

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First Revision

(Continued)



Page 5 of 5




14.00 VOLUNTARY RIDERS & APPLICABILITY MATRIX 14.01 7 Water Heating – Controlled Service 14.02 N/A Real Time Pricing Rider 14.03 30.9 Large General Service Rider 14.04 50 Controlled Service – Interruptible Load (CT Metering) Rider 14.05 50.1 Controlled Service – Interruptible Load (Self-Continaed

Metering) Rider 14.06 50.2 Controlled Service – Deferred Load Rider 14.07 50.3

50.4 50.5

Fixed Time of Delivery Rider

14.08 94.5 Voluntary Air Conditioning Control Rider (CoolSavings) 14.09 91.5 Voluntary Renewable Energy Rider (TailWinds) 14.10 N/A N/A (section reserved for future use) 14.11 91 Released Energy Access Program (REAP) Rider 14.12 50.7 Bulk Interruptible Service Application and Pricing Guide

15.00 COMMUNITIES SERVED 15.00 N/A South Dakota Communities Served

16.00 SUMMARY OF CONTRACTS WITH DEVIATIONS 16.00 Section 4,

Sheets 1-4 Summary of Contracts with Deviations

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South Dakota P.U.C. Volume IISection 13.00 – Sheet No. 1

ELECTRIC RATE SCHEDULEMandatory Riders – Applicability Matrix

First RevisionOriginal

SOUTH DAKOTA PUBLIC UTILITIES COMMISSION Filed on: November 5, 2010October 31, 2008 Approved by order dated: DATEJune 30, 2009 Docket No. EL10-__08-030

Thomas BrauseBernadeen Brutlag

Vice-President, Manager, Regulatory

ServicesAdministration

Page 1 of 3



MANDATORY RIDERS - APPLICABILITY MATRIX The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply, Voluntary Rate Riders selected by the Customer, and charges listed in the General Rules and Regulations.

<:5>=OriiRfiiiiPOWER COMPANY









Page 2 of 3



Applicability MatrixMandatory

RidersFuel Adjustment

Clause Rider

Energy Efficiency Partnership (EEP)

Cost Recovery Rider

Transmission Cost Recovery

Rider

N

Base Tariffs Section Numbers 13.01 13.04 13.05N

Residential Service 9.01 N

Residential Demand Control Service 9.02

N

Farm Service 9.03 N

Small General Service (Less than 20 kW) 10.01

N

General Service (20 kW or Greater) 10.02

N

Large General Service 10.03 N

Commercial Service - Time of Use 10.04

N

Large General Service - Time of Day 10.05

N

Standby Service 11.01 N

Irrigation Service 11.02 N

Outdoor Lighting - Energy Only 11.03 N

Outdoor Lighting 11.04 N

Municipal Pumping Service 11.05 N

Fire Sirens - Civil Defense 11.06 N

Key: = May apply = Mandatory = Not Applicable

RESIDENTIAL & FARM SERVICES

GENERAL SERVICES

OTHER SERVICES

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Clause Rider


Cost Recovery Rider


Rider

N

Base Tariffs Section Numbers 13.01 13.04 13.05 N

Water Heating - Controlled Service 14.01

N

Real Time Pricing Rider 14.02 N

Large General Service Rider 14.03 N

Controlled Service - Interruptible Load (CT Metering) Rider 14.04

N

Controlled Service - Interruptible Load (Self-Contained Metering) Rider 14.05

N

Controlled Service - Deferred Load Rider 14.06

N

Fixed Time of Delivery Rider 14.07 N

Air Conditioning Control Rider 14.08 N

Voluntary Renewable Energy Rider 14.09

N

Released Energy Rider 14.11 N

Bulk Interruptible Application and Pricing Guidelines Rider 14.12

N


VOLUNTARY RIDERS

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First Revision

SOUTH DAKOTA PUBLIC UTILITIES COMMISSION Filed on: November 5, 2010 Approved by order dated: DATE Docket No. EL10-__


Page 1 of 2



MANDATORY RIDERS - APPLICABILITY MATRIX The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply, Voluntary Rate Riders selected by the Customer, and charges listed in the General Rules and Regulations.



Clause Rider


Cost Recovery Rider


Rider

N

Base Tariffs Section Numbers 13.01 13.04 13.05N

Residential Service 9.01 N

Residential Demand Control Service 9.02

N

Farm Service 9.03 N

Small General Service (Less than 20 kW) 10.01

N

General Service (20 kW or Greater) 10.02

N

Large General Service 10.03 N

Commercial Service - Time of Use 10.04

N

Large General Service - Time of Day 10.05

N

Standby Service 11.01 N

Irrigation Service 11.02 N

Outdoor Lighting - Energy Only 11.03 N

Outdoor Lighting 11.04 N

Municipal Pumping Service 11.05 N

Fire Sirens - Civil Defense 11.06 N


RESIDENTIAL & FARM SERVICES

GENERAL SERVICES

OTHER SERVICES

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First Revision

(Continued)

SOUTH DAKOTA PUBLIC UTILITIES COMMISSION Filed on: November 5, 2010 Approved by order dated: DATE Docket No. EL10-__


Page 2 of 2





Clause Rider


Cost Recovery Rider


Rider

N

Base Tariffs Section Numbers 13.01 13.04 13.05 N

Water Heating - Controlled Service 14.01

N

Real Time Pricing Rider 14.02 N

Large General Service Rider 14.03 N

Controlled Service - Interruptible Load (CT Metering) Rider 14.04

N

Controlled Service - Interruptible Load (Self-Contained Metering) Rider 14.05

N

Controlled Service - Deferred Load Rider 14.06

N

Fixed Time of Delivery Rider 14.07 N

Air Conditioning Control Rider 14.08 N

Voluntary Renewable Energy Rider 14.09

N

Released Energy Rider 14.11 N

Bulk Interruptible Application and Pricing Guidelines Rider 14.12

N


VOLUNTARY RIDERS

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South Dakota P.U.C. Volume II Section 13.05 Sheet No. 1 ELECTRIC RATE SCHEDULE Transmission Cost Recovery Rider Page 1 of 2 Fergus Falls, Minnesota Original

SOUTH DAKOTA PUBLIC EFFECTIVE with bills UTILITIES COMMISSION Thomas Brause rendered on and after Approved by order dated: (DATE) Vice-President, March 1, 2011, Docket No. EL10-__ Administration in South Dakota

TRANSMISSION COST RECOVERY RIDER

DESCRIPTION RATE CODE

Large General Service 30-510 Controlled Service 30-511 Lighting 30-512 All Other Service 30-513

REGULATIONS: Terms and conditions of this tariff and the General Rules and Regulations govern use of this schedule.

APPLICATION OF SCHEDULE: This rate schedule is applicable to any electric service under all of the Company’s retail rate schedules.

COST RECOVERY FACTOR: There shall be included on each South Dakota Customer’s monthly bill a Transmission Cost Recovery charge, which shall be calculated before any applicable municipal payment adjustments and sales taxes as provided in the General Rules and Regulations for the Company’s electric service. The following charges are applicable in addition to all charges for service being taken under the Company’s standard rate schedules.

RATE:

TRANSMISSION COST RECOVERY Energy Charge per kWh: kWh kW Large General Service (a) 0.045 ¢/kWh $0.039 Controlled Service (b) 0.061 ¢/kWh N/A Lighting (c) 0.067 ¢/kWh N/A All Other Service 0.043 ¢/kWh N/A

(a) Rate schedules 10.03 Large General Service, 10.05 Large General Service – Time of Day, 14.02 Real Time Pricing Rider and 14.03 Large General Service Rider.

(b) Rate Schedules 14.01 Water Heating, 14.04 Interruptible Load (CT Metering), 14.05 Interruptible Load (Self-Contained Metering), 14.06 Deferred Load, and 14.07 Fixed Time of Delivery

(c) Rate Schedules 11.03 Outdoor Lighting (energy only) and 11.04 Outdoor Lighting

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South Dakota P.U.C. Volume II Section 13.05 Sheet No. 1 ELECTRIC RATE SCHEDULE Transmission Cost Recovery Rider Page 2 of 2 Fergus Falls, Minnesota Original

SOUTH DAKOTA PUBLIC EFFECTIVE with bills UTILITIES COMMISSION Thomas Brause rendered on and after Approved by order dated: (DATE) Vice-President, March 1, 2011, Docket No. EL10-__ Administration in South Dakota

DETERMINATION OF DEMAND CHARGE (LARGE GENERAL SERVICE CLASS ONLY): The demand charge shall be billed according to the demand charge as defined in the applicable rate schedule the Customer is taking service.

MANDATORY AND VOLUNTARY RIDERS: The amount of a bill for service will be modified by any Mandatory Rate Riders that must apply or Voluntary Rate Riders selected by the Customer, unless otherwise noted in this rider. See sections 12.00, 13.00 and 14.00 of the Minnesota electric rates for the matrices of riders.

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Line AllocatedNo. Amount1 GROSS REVENUE REQUIREMENT (page 3, line 31) 34,298,860$

REVENUE CREDITS (Note T) Total Allocator2 Account No. 454 (page 4, line 34) 115,163 TP 1.00000 115,1633 Account No. 456.1 (page 4, line 37) 5,805,049 TP 1.00000 5,805,0494 Revenues from Grandfathered Interzonal Transactions 20,400 TP 1.00000 20,4005 Revenues from service provided by the ISO at a discount 0 TP 1.00000 06 TOTAL REVENUE CREDITS (sum lines 2-5) 5,940,612

Wholesale Revenue Credit 17.32%

Attachment O


18 SCHEDULE 2619 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec YE20 Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected Projected21 MISO Schedule 26 Expense 220,126 223,089 239,336 211,840 207,876 161,911 187,674 194,608 205,027 204,358 166,080 178,072 2,400,00022 MISO Schedule 26 Revenue 0 0 0 0 0 0 0 0 0 0 0 0 023 Net Schedule 26 220,126 223,089 239,336 211,840 207,876 161,911 187,674 194,608 205,027 204,358 166,080 178,072 2,400,00024 South Dakota Share 9.26% 20,385 20,659 22,164 19,617 19,250 14,994 17,380 18,022 18,986 18,925 15,380 16,490 222,251

2011

Attachment 10

Notice to Otter Tail Power Company Customers Otter Tail Power Company has upgraded transmission facilities to help ensure continued reliable service and to bring renewable energy to our South Dakota customers. The South Dakota Public Utilities Commission has approved an adjustment to the Transmission charge that is part of the Resource Adjustment on your monthly electric bill beginning March 1, 2011 to recover the cost of these transmission upgrades and expansions. The current Transmission charge is:

Class ¢ / kWh $ / kW Large General Service 0.045¢ $0.039 Controlled Service 0.061¢ N/A Lighting 0.067¢ N/A All other service 0.043¢ N/A

For more information contact Customer Service at 800-257-4044 or place an inquiry from our web site at www.otpco.com.

Documents

Revised SD Trans Cover Letter · 2010. 12. 21. · REVISED PETITION OF OTTER TAIL POWER COMPANY I. INTRODUCTION. Otter Tail Power Company, (“Otter Tail or Company”), hereby petitions